Marine subsea riser systems and methods

ABSTRACT

A riser system connects a subsea source of hydrocarbons to a collection vessel. The system includes a riser, a lower end of the riser fluidly coupled to a seal stem, the seal stem in turn fluidly attached to a lower riser assembly through a polished bore receptacle. The upper end of the riser is connected to the collection vessel, the riser being maintained in a near vertical position. Methods of installing and using the riser systems for killing and cementing wells are described.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.61/479,695 filed Apr. 27, 2011.

BACKGROUND

1. Technical Field

The present disclosure relates in general to systems and methods usefulin marine hydrocarbon exploration, production, well drilling, wellcompletion, well intervention, and containment and disposal fields.

2. Related Information

Riser systems have been used during drilling, production/injection,completion/workover, and export operations. For a review, see Sparks, C.P., “Fundamentals of Marine Riser Mechanics”, 2007, especially theintroduction, pp. 1-19. FIG. 1-3a of Sparks discloses a drilling riserdeployed below a drill ship, commonly known as a mobile offshoredrilling unit (MODU). The drilling riser connects at the seabed to alower marine riser package (LMRP) and blow out preventer (BOP). U.S.published patent application number 20100025044, published Feb. 4, 2010,discloses that for well control and intervention for wells completedwith vertical subsea trees, a Completion WorkOver Riser (CWOR) system istypically used.

For other examples of riser systems, see published U.S. Pat. App. No.20070044972. Other patents mentioning further features of productionrisers systems, including quick-connect/disconnect systems include U.S.Pat. Nos. 4,234,047; 4,646,840; 4,762,180; 6,082,391; and 6,321,844.

American Petroleum Institute Recommended Practice 2RD, (API-RP-2RD,First Edition June 1998), “Design of Risers for Floating ProductionSystems (FPSs) and Tension-Leg Platforms (TLPs)” is a standard known bythose practicing in the subsea oil and gas production industry. Bai etal., Subsea Engineering Handbook, page 437, (published December 2010),also discloses riser systems. Webb et al., “Dual Activities Without theSecond Derrick—A Success Story”, SPE 112869 (2008) discloses a sparplatform, wherein the spar serves essentially as a well protectionfacility for a plurality of dry tree wells.

Polished bore receptacles (PBR) are used downhole in the oil and gasproduction industry, and typically are attached to a liner or linerhanger in a wellbore near a production zone. The PBR provides a bore toreceive a sealing member on a tubing string. PBRs are described in U.S.Pat. Nos. 4,482,014; 4,601,343; 5,743,335; 6,585,053; 6,688,395; and7,516,719 as well as U.S. Pub. Pat. Appln. 20080289813, published Nov.27, 2008. Latch rings may be used to limit the travel of tubing within aPBR, and are described in U.S. Pat. Nos. 5,413,171 and 6,202,745.

While use of riser systems and methods of installation have increased,there remains a need for a riser system to enable closed flow connectionfrom a subsea source of hydrocarbons to a drilling/well test vesselduring containment periods, and which may be employed in well test andinjection scenarios during normal production operations.

SUMMARY

In accordance with the present disclosure, marine subsea riser systemsand methods of using the same are described which reduce or overcomemany of the faults of previously known systems and methods. The systemsmay be fully or partially deployed before, during, and/or after a subseacomponent has been compromised (for example, but not limited to, asubsea well breach, damaged subsea BOP, damaged subsea riser or othersubsea conduit, damaged subsea manifold), and may be used in any marineenvironment, but are particularly useful in deep and ultra-deep subseamarine environments. In the containment and disposal context, systemsand methods described herein may be used in any marine environment whichcontains equipment that is leaking or for which a leak is imminent orsuspected to occur, either at the surface, or more particularly subsea.The apparatus, systems, and methods may also be used for exploration,production, drilling, completion, and intervention.

A first aspect of the disclosure is a riser system connecting a subseasource to a surface vessel, which may be a drill ship such as a MODU ordrilling rig, the system comprising: a near-vertical riser comprising alower end and an upper end, the upper end of the riser mechanically andfluidly connected to the surface vessel; a seal stem, a lower end of theriser fluidly and mechanically connected to the seal stem, the seal stemcomprising one or more exterior elastomeric sealing elements; a lowerriser assembly (LRA) comprising a member having a longitudinal bore, alower end, an upper end, and an external surface, the member comprisingsufficient intake ports extending from the external surface to the boreto accommodate flow of hydrocarbons from a hydrocarbon fluid source, atleast one of the intake ports fluidly connected to the subsea source; apolished bore receptacle (PBR) comprising a polished bore, a lower endof the PBR fluidly and mechanically connected to the upper end of themember; the exterior elastomeric sealing elements of the seal stemsealingly engaging the polished bore to create a pressure-tight flowpath through the PBR, seal stem, and riser.

In certain system embodiments the riser includes a plurality of riserjoints, such as drill pipe joints. In certain system embodiments thevessel further includes a dynamic positioning system, and the riser ismaintained in the near-vertical position by the dynamic positioningsystem. As used herein the phrases “near-vertical” and “substantiallyvertical” are used interchangeably and mean that the riser profile isgenerally vertical, but that some horizontal offset and vertical setdownat the surface are allowed. Riser offset and setdown influences riserstretch, and hence, riser tension and sag. Some riser axial stretch (andshrink) is allowed, owing to vessel lateral and vertical movements, andriser internal changes due to temperature, pressure and/or fluid densitychanges. The term “near-vertical” is also meant to distinguish the riserfrom catenary risers and exports lines. In certain system embodimentsthe member includes a subsea wellhead housing having a lower end and anupper end, the lower end capped with an end forging that is attached toa foundation in the seabed.

A second aspect of this disclosure is a method of installing a subseamarine riser system, the method comprising: attaching a first end of amember to an end forging, a first end of a polished bore receptacle(PBR) to the member, the PBR comprising a polished bore and a guidefunnel on an end opposite the first end, and attaching the end forgingto a subsea foundation so that the PBR is substantially vertical;directing a drill string riser toward the guide funnel, the drill stringcomprising a seal stem comprising one or more elastomeric seal elements;and stabbing the seal stem into the PBR and establishing a pressuretight seal between the elastomeric seal elements and the polished bore.

Certain method embodiments include connecting a subsea flexible conduitand gooseneck assembly to the member and to a subsea source. In certainembodiments the latter steps may be accomplished using one or moresubsea installation vessels, such as remotely-operated vehicles (ROVs).In certain other method embodiments the steps of directing and stabbingare performed using a mobile offshore drilling unit (MODU). Certainmethod embodiments include assisting the directing and/or the stabbingsteps using one or more ROVs. Certain method embodiments includeconstructing the drill string riser using high strength steel tubularsusing threaded coupled connectors. Still other installation methodsinclude supporting the PBR using structural supports extending from thesubsea foundation to a point approximately midway up the PBR.

A third aspect of this disclosure is a method of producing a fluid froma subsea source, the method comprising: deploying subsea from a surfacevessel a lower riser assembly (LRA) comprising a member having alongitudinal bore, a lower end, an upper end, and an external surface,the member comprising sufficient intake ports extending from theexternal surface to the bore to accommodate flow of hydrocarbons from ahydrocarbon fluid source, the LRA having attached thereto a polishedbore receptacle (PBR) comprising a polished bore, a lower end of the PBRfluidly and mechanically connected to the upper end of the member;fluidly connecting at least one of the intake ports to the subsea sourceusing a flexible conduit; lowering a riser from the surface vessel, theriser comprising a lower end and an upper end, the upper end of theriser mechanically and fluidly connected to the surface vessel, theriser being maintained in an erect substantially vertical position bydynamic positioning of the vessel, the riser comprising a seal stemfluidly and mechanically connected to its lower end, the seal stemcomprising one or more exterior elastomeric sealing elements; stabbingthe seal stem into the PBR, the exterior elastomeric sealing elements ofthe seal stem sealingly engaging the polished bore to create apressure-tight flow path through the PBR, seal stem, and riser; andinitiating flow from the subsea source through the subsea flexibleconduit, the LRA, the PBR, the seal stem, and the riser.

A fourth aspect of the disclosure is a method of killing a wellproducing a fluid from a subsea source, the method comprising: deployingsubsea from a surface vessel a lower riser assembly (LRA) comprising amember having a longitudinal bore, a lower end, an upper end, and anexternal surface, the member comprising sufficient outtake portsextending from the bore to the external surface to accommodate flow of akill density fluid from the surface vessel to a hydrocarbon fluidsource, the LRA having attached thereto a polished bore receptacle (PBR)comprising a polished bore, a lower end of the PBR fluidly andmechanically connected to the upper end of the member; fluidlyconnecting at least one of the outtake ports to the subsea source usinga flexible conduit; lowering a riser from the surface vessel, the risercomprising a lower end and an upper end, the upper end of the risermechanically and fluidly connected to the surface vessel, the riserbeing maintained in an erect substantially vertical position by dynamicpositioning of the vessel, the riser comprising a seal stem fluidly andmechanically connected to its lower end, the seal stem comprising one ormore exterior elastomeric sealing elements; stabbing the seal stem intothe PBR, the exterior elastomeric sealing elements of the seal stemsealingly engaging the polished bore to create a pressure-tight flowpath through the riser, seal stem, and PBR; and initiating flow of killdensity fluid from the surface vessel through the riser, seal stem, PBR,LRA, and subsea flexible conduit.

A fifth aspect of the disclosure is a method of cementing a subseawellbore using a surface marine vessel, the method comprising: deployingsubsea from a surface vessel a lower riser assembly (LRA) comprising amember having a longitudinal bore, a lower end, an upper end, and anexternal surface, the member comprising sufficient outtake portsextending from the bore to the external surface to accommodate flow of acementing fluid from the surface vessel to a hydrocarbon fluid source,the LRA having attached thereto a polished bore receptacle (PBR)comprising a polished bore, a lower end of the PBR fluidly andmechanically connected to the upper end of the member; fluidlyconnecting at least one of the outtake ports to the subsea source usinga flexible conduit; lowering a riser from the surface vessel, the risercomprising a lower end and an upper end, the upper end of the risermechanically and fluidly connected to the surface vessel, the riserbeing maintained in an erect substantially vertical position by dynamicpositioning of the vessel, the riser comprising a seal stem fluidly andmechanically connected to its lower end, the seal stem comprising one ormore exterior elastomeric sealing elements; stabbing the seal stem intothe PBR, the exterior elastomeric sealing elements of the seal stemsealingly engaging the polished bore to create a pressure-tight flowpath through the riser, seal stem, and PBR; and initiating flow of acementing fluid from the surface vessel through the riser, seal stem,PBR, LRA, and subsea flexible conduit.

Methods described herein may benefit from the methods described inassignee's Attorney Docket No. 500010-00 corresponding to U.S.Provisional Application No. 61/479,769, filed Apr. 27, 2011,incorporated herein by reference, to establish flow up the seal stem andriser. The 500010-00 application describes deploying a riser and acollection tool subsea upstream from a plume of hydrocarbons emanatingfrom a subsea source of hydrocarbons. In the present application, thecollection tool would be the seal stem. Certain methods might includedisplacing seawater from the riser and seal stem by forcing low-densityfluid into the riser and seal stem. When bubbles of low-density fluidare observed emanating from the lower end of the seal stem the methodincludes positioning the seal stem connected to a distal end of theriser to stab the seal stem into a PBR previously secured to the seabedwhile the riser and seal stem remain filled with the low-density fluid,the exterior elastomeric sealing elements of the seal stem sealinglyengaging the polished bore of the PBR to create a pressure-tight flowpath through the riser, seal stem, and PBR. Flow of the low-densityfluid may then be reduced gradually and a choke opened gradually,establishing flow of hydrocarbons up the seal stem and riser.

These and other features of the systems, apparatus, and methods of thedisclosure will become more apparent upon review of the briefdescription of the drawings, the detailed description, and the claimsthat follow.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of this disclosure and otherdesirable characteristics can be obtained is explained in the followingdescription and attached drawings in which:

FIG. 1A is a schematic side elevation view, partially in cross-section,of one system and method embodiment within the present disclosure;

FIG. 1B is a detailed cross-section of a portion of the embodiment ofFIG. 1;

FIG. 2 is a schematic side elevation view, partially in cross-section ofa seal stem useful in systems and methods within the present disclosure;

FIGS. 3A and 3B are schematic side elevation views, partially incross-section, of one embodiment of a lower riser assembly, PBR andgooseneck assembly in accordance with the present disclosure;

FIGS. 4A and 4B are schematic side elevation views, partially incross-section, of one embodiment of a subsea manifold and gooseneckassembly;

FIG. 5 is a schematic side elevation view, of a PBR attached to awellhead and subsea pile foundation in accordance with an embodiment ofthe present disclosure;

FIG. 6 is a schematic perspective view of the structure illustratedschematically in FIG. 5;

FIG. 7 is a detailed schematic cross-sectional view of a PBR and sealstem useful in systems and methods of the present disclosure;

FIG. 8 is a schematic cross-sectional view of a pressure balancingfeature that may be used in certain system and method embodiments; and

FIGS. 9-12 are logic diagrams of four method embodiments in accordancewith the present disclosure.

It is to be noted, however, that the appended drawings are not to scaleand illustrate only typical embodiments of this disclosure, and aretherefore not to be considered limiting of its scope, for the disclosuremay admit to other equally effective embodiments. Identical referencenumerals are used throughout the several views for like or similarelements.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to providean understanding of the disclosed methods, systems, and apparatus.However, it will be understood by those skilled in the art that themethods, systems, and apparatus may be practiced without these detailsand that numerous variations or modifications from the describedembodiments may be possible. All U.S. published patent applications andU.S. Patents referenced herein are incorporated herein by reference. Inthe event definitions of terms in the referenced patents andapplications conflict with how those terms are defined in the presentapplication, the definitions for those terms that are provided in thepresent application shall be deemed controlling.

Described herein are riser systems connecting a subsea source to asurface vessel, which may be a drill ship such as a MODU or other vesselincluding a drilling rig. Certain embodiments include a near-verticalriser having a lower end and an upper end, the upper end of the risermechanically and fluidly connected to the surface vessel. Certain systemembodiments described herein include a seal stem, a lower end of theriser fluidly and mechanically connected to the seal stem, the seal stemincluding one or more exterior elastomeric sealing elements. Certainembodiments further include a lower riser assembly (LRA) including agenerally cylindrical member having a longitudinal bore, a lower end, anupper end, and an external generally cylindrical surface, the memberincluding sufficient intake ports extending from the external surface tothe bore to accommodate flow of hydrocarbons from a hydrocarbon fluidsource, at least one of the intake ports fluidly connected to the subseasource. Certain systems include a polished bore receptacle (PBR) havinga polished bore, a lower end of the PBR fluidly and mechanicallyconnected to the upper end of the generally cylindrical member. Incertain embodiments the exterior elastomeric sealing elements of theseal stem sealingly engage the polished bore to create a pressure-tightflow path through the PBR, seal stem, and riser.

In certain system embodiments the seal stem may include a latch ringthat allows reduction of travel of the seal stem in the PBR. In certainsystem embodiments the subsea source is fluidly connected to one of theintake ports via a flexible conduit and a gooseneck assembly. In certainsystem embodiments the wellhead housing may further include one or moreports allowing pressure and/or temperature monitoring. In certain systemembodiments the PBR is threaded into the wellhead housing.

In certain system embodiments the riser upper end may be connected to adrill ship or drilling rig on the vessel.

In certain system embodiments the LRA may further include one or morehot stab ports for ROV intervention and/or maintenance. In certainsystem embodiments the lower end of the LRA may be connected to a subseamooring, and may further comprise one or more structural supports forthe PBR extending from the subsea mooring to a point about midway up thePBR. In certain system embodiments the subsea mooring may be a suctionpile, although any stable and fixed object on the seabed may be used asa foundation. In certain system embodiments an upper end of the PBR mayinclude a guide funnel.

In certain system embodiments at least some portions of the riser mayinclude sections of pipe joined by threaded joints. In certain systemembodiments the riser joints may be constructed using high strengthsteel tubulars using threaded coupled connectors.

In certain system embodiments the LRA may be fluidly connected to anactive subsea wellhead via one or more flexible conduits. In certainsystem embodiments the subsea flexible conduit may include a lazy waveflexible jumper with at least one distributed buoyancy module connectedfrom the base of the riser to a subsea manifold on the seafloor, themanifold fluidly connected to the subsea source or sources.

In certain system embodiments the LRA may further include an additionalassembly or sub fluidly connecting the LRA to a source of a functionalfluid. In certain system embodiments the LRA may include one or more ROVhot-stab ports allowing a flow assurance fluid to flow into both the LRAand the riser, the flow assurance fluid selected from the groupconsisting of nitrogen or other gas phase, heated seawater or otherwater, or organic chemicals such as methanol, and the like.

In certain system embodiments the seal between the PBR and the seal stemmay be such that the riser and seal stem may be disconnected from thePBR, allowing the PBR and LRA to be disconnected from the surface vesselin either an emergency or planned event (i.e. drive/drift off orhurricane evacuation).

In certain system embodiments the gooseneck may include, in orderstarting at the generally cylindrical member, an API flange, a sectionof tubing, a high pressure subsea connector, a subsea API connector andAPI flange, and a bend restrictor.

In certain system embodiments the generally cylindrical member mayinclude a forged, high-strength steel intake spool fluidly connected toa gooseneck assembly, the gooseneck assembly fluidly connected to aflexible conduit, the generally cylindrical member also including aconnector allowing connection to a source of a functional fluid.

In certain system embodiments the subsea source may be a malfunctioningsubsea BOP, the system further comprising one or more umbilicals, one ofthe umbilicals fluidly connected to locations on the subsea BOP selectedfrom the group consisting of a kill line of the subsea BOP, a choke lineof the subsea BOP, and both the kill and choke lines of the subsea BOP.In certain system embodiments the subsea source may be a malfunctioningsubsea BOP, the system further including one or more umbilicals, one ofthe umbilicals fluidly connected to a subsea BOP stack manifold.

In certain system embodiments the riser system may further include oneor more umbilicals, wherein one of the umbilicals is fluidly connectedto a subsea manifold. In certain other system embodiments the risersystem may further include a modified bumper sub in the drill string.

In yet other system embodiments the riser system may further include theseal stem extending into the generally cylindrical member a distancesufficient to create upper and lower seals between the generallycylindrical member and the seal stem, wherein the intake ports arebetween the upper and lower seals, the seal stem further including oneor more inlet ports positioned between the upper and lower seals.

As used herein the phrase “subsea source” includes, but is not limitedto: 1) production sources such as subsea wellheads, subsea BOPs, othersubsea risers, subsea manifolds, subsea piping and pipelines, subseastorage facilities, and the like, whether producing, transporting and/orstoring gas, liquids, or combinations thereof, including both organicand inorganic materials; and 2) subsea containment sources of all types,including leaking or damaged subsea BOPs, risers, manifolds, tanks, andthe like. Certain system embodiments include those wherein thecontainment source is a failed subsea blowout preventer.

Still other system and method embodiments include those wherein theriser and/or the LRA may comprise one or more vent subs to facilitatecirculation of a flow assurance fluid, for example a hydrate-preventingfluid, for example a gas phase to contain either a low or high pressuregas cushion, or heated seawater or other water, or methanol or otherorganic fluid, or combination of these. Certain hydrate inhibitionmethod embodiments include those wherein the hydrate-inhibitor liquidchemical may be selected from the group consisting of alcohols andglycols. In certain embodiments a flow assurance fluid may include a gasatmosphere consisting essentially of nitrogen, where the phrase“consisting essentially of nitrogen” means that the gas atmosphere ismostly nitrogen plus any allowable impurities that would not affect theability of the nitrogen to prevent hydrocarbon gas hydrate formation. Incertain system embodiments the vent sub may include one or more valvescontrollable by a subsea vehicle.

Certain system embodiments include those wherein the LRA gooseneckassembly may include at least one emergency shutdown valve. In certainembodiments the emergency shutdown valve may include onehydraulically-operated and one electrically-operated emergency shutdownvalve, one or both controlled using an umbilical connected to acollection vessel at the surface.

Certain system embodiments include those wherein the LRA gooseneckassembly may include a flow control valve for controlling flow in theriser.

Certain system embodiments include those wherein the subsea flexibleconduit may include a lazy wave flexible jumper with distributedbuoyancy modules connected to the subsea flexible conduit randomly ornon-randomly from a point of connection of the subsea flexible conduitto the gooseneck assembly to a subsea manifold on the seafloor, themanifold fluidly connected to the subsea source or sources.

In certain system embodiments the pile foundation may be a suction pilefoundation in the seabed, the suction pile foundation including aplunger.

Certain system embodiments include external wet insulation on theexterior surface of the riser for flow assurance. In certain embodimentsthe wet insulation may include a syntactic foam material. In certainembodiments the syntactic foam material may include a plurality oflayers of syntactic polypropylene.

Still other system and method embodiments include those wherein thesystem may include one or more concentric free-standing riserspositioned laterally apart in the sea from the system including a riser,seal stem, PBR, and LRA. In such embodiments, the latter system may bedeployed quickly while awaiting arrival of the free-standing risersystem. In certain embodiments, the two systems may be used in the samecontainment or production operation.

Certain installation method embodiments may include, in the event of ahurricane or planned disconnect, disconnecting the riser and seal stemfrom the PBR in a controlled manner using upward force, which force mayhave a lateral component. Even if not performed in a controlled manner,such as during an unplanned weather event, or ship malfunction event,the systems may be designed such that the seal stem may disconnect fromthe PBR without extensive damage to the seal stem, riser, and PBR.

Systems and methods of this disclosure may include well interventionoperations. The systems and methods described herein may provide otherbenefits, and the methods are not limited to particular end uses; otherobvious variations of the apparatus, systems and methods may beemployed.

The primary features of the systems, methods, and apparatus of thepresent disclosure will now be described with reference to the drawingfigures, after which some of the construction and operational detailswill be further explained. The same reference numerals are usedthroughout to denote the same items in the figures.

In accordance with the present disclosure, illustrated schematically inFIG. 1A is an embodiment 100 of a system of this disclosure that may beemployed for deepwater subsea containment, disposal, production, andwell intervention. While many of the apparatus, systems, and methodsdescribed herein were developed and used in the context of containmentand disposal, it is explicitly noted that the apparatus, systems, andmethods described herein, many features of which have never before beenused or even contemplated heretofore, are not restricted to containmentand disposal operations, but may be used in conjunction with any “subseasource”, as that term is defined herein. In embodiment 100 of FIG. 1A,the system includes a lower riser assembly or LRA, in this embodimentincluding a wellhead housing 2. The wellhead housing 2 can be asubstantially cylindrical member. Wellhead housing 2 fluidly andmechanically connects to a polished bore receptacle or PBR 4, whichincludes a polished bore 5 as more clearly identified in the detailedcross-sectional view of FIG. 1B. PBR accepts in its polished bore 5 aseal stem 8. Seal stem 8 includes one or more elastomeric seals 6, againas more clearly detailed in FIG. 1B. Seal stem 8 may include a latchring 9, which functions (when present) to reduce travel of seal stem 8within PBR 4. Latch ring 9 functions by holding elastomeric seals 6 in astatic position during most of the operating range, thus increasingconfidence in the sealing mechanism and increasing the seal longevity,while increasing the operating pressure range of systems using a latchring. FIG. 7 is a detailed cross-section of a latch ring. Seal stem 8 isattached, typically by threaded connection, to a drill string 10composed of a number of drill pipe sections. During installation from asurface vessel 28 at sea surface 50, a funnel-shaped guide 12 on PBR 4helps guide drill string 10 and seal stem 8 into PBR 4. Optionallyincluded in drill string 10 is a modified bumper sub 20 having a head 22that may swivel in response to rotation of ship 28. Modified bumper sub20 may also include a telescoping section 21, and may have seals andsplines removed to afford less friction in operation. Drill stringsection 24 extends up to and fluidly and mechanically connects withvessel 28 in a known fashion.

Still referring to FIG. 1A, a flexible jumper 30 is illustrated asfluidly connected to a gooseneck 18 and a male/female subsea connector26, and wellhead 2, as more fully detailed in the description of FIGS.3A and 3B hereinbelow. Wellhead 2 is affixed to a bottom plate 96,typically and most conveniently by welding, although this is notstrictly required, other means such as bolting being possible. Bottomplate 96 is in turn attached by welding, bolting, or some othermechanism to a seabed foundation 54, which may be any solid foundation.In embodiment 100, foundation 54 is a suction pile sunken into seabed 52just so far that a portion of suction pile 54 remains above seabed 52.Gooseneck 18 is supported by a buoyancy device 32 attached via a tetherchain 34 to a rigging adapter 80. Rigging adapter 80 may have a multipleholes 81 for applying buoyant support at different angles to gooseneck18 as required or desired.

Turning now to FIG. 2, there is schematically illustrated in sideelevation and partial cross-section a seal stem 8 that may be useful inthe systems and methods of the present disclosure. As an example, sealstem 8 may presently be purchased from Allamon Tool Company, Inc.,Montgomery, Tex., USA. As illustrated, seal stem 8 is threadablyconnected to a drill string section 10. Seal stem 8 includes an internalbore 11, and several elastomeric sealing elements 56 (three in thisembodiment) positioned between four brass sleeves 58A, B, C, and D. Sealstem end 60 is the end that is stabbed into PBR 4 during installation.In operation, as seal stem 8 is forced up or down by pressure and/ortemperature changes in fluid traversing bore 11, elastomeric seals 56resist this movement by forming a pressure tight seal between the sealstem and polished bore 5 of PBR 4. Seal stem 8 typically includes anexpandable metal body 13 having a pressure rating of about 10,000 psi(69 Mpa) at temperatures of about 300-400° F. (about 150-200 C) anddiameters ranging from about 5 to about 14 inches (from about 13 toabout 35 cm), or from about 5 to about 7 inches (about 13 to about 18cm). PBRs are available from several sources, including WeatherfordInternational and Baker Hughes.

FIGS. 3A and 3B are schematic side elevation views, partially incross-section, of one embodiment of a lower riser assembly, PBR andgooseneck assembly in accordance with the present disclosure. In thisembodiment, the wellhead 2 is mounted on a subsea PBR manifold 62. Apair of supports 14, 16 are illustrated, which provide structuralsupport for PBR 4 during instances when seal stem 8 is being removedfrom PBR 4, either by choice or unintentionally. A touchdown point 64 isindicated where flexible conduit 30 would intersect seabed 52 were it totravel straight. Flexible conduit 30 may be in the form of a lazy waveusing one or more buoyancy modules, 32, to control location of touchdownpoint 64. Distance of touchdown point 64 from foundation (manifold 62 inthis embodiment) is regulated by various standards, such as published bythe API. As more clearly illustrated in FIG. 3B, gooseneck 18 is fluidlyand mechanically connected to wellhead housing 2 by a series of subseaconnectors and flanges, including male/female subsea connector 26, whichincludes an ROV-operable clamp 66, such as available under the tradedesignation OPTIMA from Vector Group, Inc. Houston, Tex. (USA), an APIflange 69 connecting gooseneck 18 to wellhead housing 2, a bottom endfitting 68 connecting flexible jumper 30 to an API 7 1/16 inch (18 cm)5KSI (34 MPa) connector 72, an articulating RAC hub 70 (available fromOil States Industries, Inc. Arlington, Tex. (USA), an RAC connector 74(also available from Oil States Industries, Inc.), and API 3⅛-inch (8cm) connector (15K, 103 MPa) 76, and a subsea adapter 78 which allowsgooseneck 18 to be fluidly and mechanically connected to connector 76.

FIGS. 4A and 4B are schematic side elevation views, partially incross-section, of one embodiment of a subsea manifold 94 and gooseneckassembly 82 that may be useful in practicing the methods and systems ofthe present disclosure. Manifold 94 may be a choke/kill manifold (CKM)for a subsea BOP, for example. Flexible jumper 30 is illustrated, thesame flexible jumper 30 from FIGS. 3A and 3B. A second touchdown point65 is noted, as well as a swivel connector 92 connecting gooseneck 82and manifold 94. Supports 95 extend from manifold 94 to swivel connector92. Another rigging adapter 90 is provided on gooseneck 82, andgooseneck 82 is fluidly and mechanically connected to flexible jumper 30via a 3-inch to 7-inch (7.6 cm to 18 cm) adapter 88, and API 7 1/16-inch(18 cm) (5K, 34 MPa) adapter 86, and a bottom end fitting 84.

FIG. 5 is a schematic side elevation view of a PBR attached to awellhead and subsea pile foundation in accordance with an embodiment ofthe present disclosure, and FIG. 6 is a schematic perspective view ofthe structure illustrated schematically in FIG. 5. Subs 98 and 102 areprovided in this embodiment connected to wellhead housing 2. Sub 98 maybe, for example a vent or connection for a pressure relief valve (PRV),while sub 102 may provide a connection for a functional fluid, such as aflow assurance fluid, for example, but not limited to methanol, glycol,or heated water. FIG. 6 illustrates four supports 14, 15, 16, and 17 forPBR extending from a top of suction pile 54 to a midpoint up PBR 4.Support 14, 15, 16, and 17 may include, for example, carbon steel, orstainless steel, or titanium, or other exotic corrosion-resistant metal,or non-corrosion resistant metal having a corrosion-resistant coating.Supports 14, 15, 16, and 17 may each form an angle “α” measured from aline parallel to plate 96 ranging from about 45 to about 85 degrees, orfrom about 70 to about 80 degrees. FIG. 6 illustrates suction pile 54supported on a skid 104, which may be on vessel 28, for example. Suctionpile includes a pump-out connection, 106.

FIG. 7 is a detailed schematic cross-sectional view of a PBR and sealstem 8 useful in systems and methods of the present disclosure,illustrating in detail a latch ring 9 having upper and lower beveledouter edges 9A, 9B, respectively, as well as a rectangular inner edge9C. Outer beveled edges 9A, 9B fit into respective beveled edges 4A, 4Bin PBR 4, and rectangular edge 9C fits in to a square groove 3 in sealstem 8.

FIG. 8 is a schematic cross-sectional view of a pressure-balancingfeature that may be used in certain system and method embodiments. Incertain embodiments, wellbore conditions may be such that they forceseal stem 8 and riser 10 upwards, and seal stem 8 out of PBR 4. Incertain embodiments, seal stem 8 may be modified to include a bottom endplate 110 and one or more orifices 112. In addition, wellhead 2 may bemodified to include seal rings, collets, dog connectors, or similarconnections 114, 116, as illustrated in FIG. 8, forming a chamber orannulus 118 between wellhead housing 2 and seal stem 8. As fluid entersannulus 118 from gooseneck 18, pressure is now equalized in upward anddownward directions, and since the annular area is the same in bothdirections, the net effect is zero force up or down, and seal stem is nolonger forced upward out of PBR 4.

FIGS. 9-12 are logic diagrams of four method embodiments in accordancewith the present disclosure. Method embodiment 200 illustrated in FIG. 9is one embodiment of a method of installing a subsea marine risersystem, the method including the steps of attaching a first end of amember, for example a generally cylindrical member, to a foundationplate (box 202). The method then includes attaching a first end of apolished bore receptacle (PBR) to the member, the PBR including apolished bore and a guide funnel on an end opposite the first end (box204), then attaching the foundation plate to a subsea foundation so thatthe PBR is substantially vertical (box 206). The method continues bydirecting a drill string riser toward the guide funnel, the drill stringincluding a seal stem including one or more elastomeric seal elements(box 208), and stabbing the seal stem into the PBR and establishing apressure tight seal between the elastomeric seal elements and thepolished bore (box 212). A subsea flexible conduit and gooseneckassembly is then connected to the member and to a subsea source using asubsea installation vessel (box 216). As illustrated in FIG. 9, steps208 and 212 may be carried out using a MODU, box 218, and at least twosteps may be assisted by one or more ROVs, as indicated in boxes 210,214.

FIG. 10 illustrates another method embodiment 300, which is a method ofproducing a fluid from a subsea source. In embodiment 300, a first stepincludes deploying subsea from a surface vessel a lower riser assembly(LRA) including a member, for example a generally cylindrical member,having a longitudinal bore, a lower end, an upper end, and an externalsurface, the member including sufficient intake ports extending from theexternal surface to the bore to accommodate flow of hydrocarbons from ahydrocarbon fluid source, the LRA having attached thereto a polishedbore receptacle (PBR) including a polished bore, a lower end of the PBRfluidly and mechanically connected to the upper end of the member (box302). Method embodiment 300 continues with the steps of fluidlyconnecting at least one of the intake ports to the subsea source using aflexible conduit (box 304), and lowering a riser from the surfacevessel, the riser including a lower end and an upper end, the upper endof the riser mechanically and fluidly connected to the surface vessel,the riser being maintained in a substantially vertical position bydynamic positioning of the vessel, the riser including a seal stemfluidly and mechanically connect to its lower end, the seal stem,including one or more exterior elastomeric sealing elements (box 306).Method embodiment 300 continues with the steps of stabbing the seal steminto the PBR, the exterior elastomeric sealing elements of the seal stemsealingly engaging the polished bore to create a pressure-tight flowpath through the PBR, seal stem, and riser (box 308), and initiatingflow from the subsea source through the subsea flexible conduit, theLRA, the PBR, the seal stem, and the riser (box 310).

Another method embodiment 400 is illustrated in logic diagram format inFIG. 11. Embodiment 400 includes a method of killing a well producing afluid from a subsea source. The first step of method embodiment 400includes the step of deploying subsea from a surface vessel a lowerriser assembly (LRA) including a member, for example a generallycylindrical member, having a longitudinal bore, a lower end, an upperend, and an external surface, the member including sufficient outtakeports extending from the bore to the external surface to accommodateflow of a kill density fluid from the surface vessel to a hydrocarbonfluid source, the LRA having attached thereto a polished bore receptacle(PBR) including a polished bore, a lower end of the PBR fluidly andmechanically connected to the upper end of the member (box 402). Methodembodiment 400 continues with the steps of fluidly connecting at leastone of the outtake ports to the subsea source using a flexible conduit(box 404), and lowering a riser from the surface vessel, the riserincluding a lower end and an upper end, the upper end of the risermechanically and fluidly connected to the surface vessel, the riserbeing maintained in a substantially vertical position by dynamicpositioning of the vessel, the riser including a seal stem fluidly andmechanically connected to its lower end, the seal stem including one ormore exterior elastomeric sealing elements (box 406). Method embodiment400 then includes the steps of stabbing the seal stem into the PBR, theexterior elastomeric sealing elements of the seal stem sealinglyengaging the polished bore to create a pressure-tight flow path throughthe riser, seal stem, and PBR (box 408), and initiating flow of killdensity fluid from the surface vessel through the riser, seal stem, PBR,LRA, and subsea flexible conduit (box 410).

Another method embodiment 500 is illustrated in logic diagram format inFIG. 12. Embodiment 500 is a method of cementing a subsea wellbore usinga surface marine vessel. The first step of method embodiment 500includes the step of deploying subsea from a surface vessel a lowerriser assembly (LRA) including a member, for example a generallycylindrical member, having a longitudinal bore, a lower end, an upperend, and an external generally cylindrical surface, the member includingsufficient outtake ports extending from the bore to the external surfaceto accommodate flow of a cementing fluid from the surface vessel to ahydrocarbon fluid source, the LRA having attached thereto a polishedbore receptacle (PBR) including a polished bore, a lower end of the PBRfluidly and mechanically connected to the upper end of the member (box502). Method embodiment continues with the steps of fluidly connectingat least one of the outtake ports to the subsea source using a flexibleconduit (box 504), and then lowering a riser from the surface vessel,the riser including a lower end and an upper end, the upper end of theriser mechanically and fluidly connected to the surface vessel, theriser being maintained in an erect substantially vertical position bydynamic positioning of the vessel, the riser including a seal stemfluidly and mechanically connected to its lower end, the seal stemincluding one or more exterior elastomeric sealing elements (box 506).Method embodiment 500 then includes the steps of stabbing the seal steminto the PBR, the exterior elastomeric sealing elements of the seal stemsealingly engaging the polished bore to create a pressure-tight flowpath through the riser, seal stem, and PBR (box 508), and initiatingflow of a cementing fluid from the surface vessel through the riser,seal stem, PBR, LRA, and subsea flexible conduit (box 510).

It should be noted that other vessels may be present duringinstallation, or during containment and production operations. Forexample, separate ship-based floating production and storage systems onsea surface 50 may be present, as well as processing vessels, collectionvessels, service vessels, and the like. Other vessels may be providedfor subsea installation, operational and ROV assistance to system 100,and hydrate prevention and remediation, if needed. Other system 100components may a choke/kill manifold (“CKM”); a flare or other optionalgas disposal/containment apparatus, such as a natural gas handling andstorage system and method as described in assignee's U.S. Pat. No.6,298,671; a multipurpose intervention vessel, which may include varioussubsea connector conduits, umbilicals from chemical dispersant andhydrate inhibition systems; a hydrate inhibition system service vesselwhich may also supply power and/or hydraulic assistance through one ormore umbilicals; a subsea umbilical distribution box, and electricalpower and/or hydraulic umbilical lines. A riser tension monitoringsystem may be provided, and may include a plurality of such monitoringsystems randomly or non-randomly spaced along the riser. The ability topump a functional fluid, such as methanol or heated water, into ROV hotstab receptacles is another option, as is the ability to pump afunctional fluid such as nitrogen or other gas phase into the bottom ofthe riser or at a subsea manifold into the flexible subsea conduits as away to get the fluid underneath an actual or potential, complete orpartial hydrate plug or other flow restriction.

Suction pile assemblies useful in the systems and methods within thepresent disclosure and their installation are described for example inUS published patent application 2002/0122696, and typically include acylindrical casing, a top plate, a flanged connection near or on its topplate for pumping seawater in or out of cylindrical casing, and variousconnections to help manipulate the suction pile. A funnel connection andvertical extension provide guidance when landing a piston, such asavailable from Balltec, of Lancashire, UK. Installation of a suctionpile in the seabed proceeds by pumping out seawater from the device.Subsea pressure forces the cylindrical casing into the seafloor. Thesuction piles may be 14 feet (4.3 m) in diameter and 70 feet (21 m)long.

The LRA in one embodiment can include a 15K Vetco H-4 subsea wellhead,specially machined with 2×7⅙ inch (5×18 cm) 10,000 psi (69 MPa) inletsto accommodate either multiple flexible jumper connections, or oneproduction jumper and an ROV interface for methanol injection.

Systems and methods of this disclosure may employ a riser positioningsystem and riser tension monitoring sub-system. A riser positioningsystem typically includes a riser position clamp and a pair of acousticsources or beacons. Suitable acoustic beacons are available fromSonardyne International Ltd in the UK, and from Sonardyne Inc., Houston,Tex. Acoustic positioning is well known and requires no furtherexplanation herein; however, its use in subsea containment and disposalmethods and systems is not known. The riser position clamp with twoacoustic beacons may be deployed anywhere on the riser. These beaconsmay be integrated with the containment vessel dynamic positioning (DP)systems in order to provide continuous relative location of the top ofthe riser that feeds directly into the management of vesselstation-keeping limits. The riser tension monitoring unit may bestrain-based and may be installed anywhere along the length of theriser, and in multiple locations.

In embodiments, certain connections may be expected to experience heavyfatigue. The teachings of Shilling, et al., “Development of FatigueResistant Heavy Wall Riser Connectors for Deepwater HPHT Dry Tree RiserSystems”, OMAE2009-79518, may be useful in these embodiments.

The systems and methods of the present disclosure are scalable over awide range of water depths, well pressures and conditions. The riserideally will be capable of handling over 40,000 bbl. per day (about 4800cubic meters per day) with a 6-inch (15 cm) ID flow path in the riser.The riser joints may for example include 0.563-inch (1.430 cm) wallthickness X-80 steel material rated to 6,500 psi (45 MPa). X-80 steelmay be used in order to successfully weld on premium riser connectorsthat had external and internal metal-to-metal seals and met the fatigueperformance requirements of the anticipated service life. (X-80, or X80,is a number associate with American Petroleum Institute (API) standard5L).

In general, the riser may have an outer diameter (OD) ranging from about1 inch up to about 50 inches (2.5 cm to 127 cm), or from about 2 inchesup to about 40 inches (5 cm to 102 cm), or from about 4 inches up toabout 30 inches (10 cm to 76 cm), or from about 6 inches up to about 20inches (15 cm to 51 cm).

Over the past several years, BP has participated in the development of acomprehensive 15/20 Ksi (103/138 MPa) dry tree riser qualificationprogram which focuses on demonstrating the suitability of using highstrength steel materials and specially designed thread and coupled (T&C)connections that are machined directly on the riser joints at the mill.See Shilling et al., “Development of Fatigue Resistant Heavy Wall RiserConnectors for Deepwater HPHT Dry Tree Riser Systems”, OMAE2009-79518.These connections may eliminate the need for welding and facilitate theuse of high strength materials like C-110 and C-125 metallurgies thatare NACE qualified. As used herein, “NACE” refers to the corrosionprevention organization formerly known as the National Association ofCorrosion Engineers, now operating under the name NACE International,Houston, Tex. Use of high strength steel and other high strengthmaterials significantly reduces the wall thickness required, enablingriser systems to be designed to withstand pressures much greater thancan be handled by X-80 materials and installed in much greater waterdepths due to the reduced weight and hence tension requirements. The T&Cconnections eliminate the need for third party forgings and expensivewelding processes—considerably improving system delivery time andoverall cost. It will be understood, however, that the use of thirdparty forgings and welding is not ruled out for risers and LRAsdescribed herein, and may actually be preferable in certain situations.The skilled artisan, having knowledge of the particular depth, pressure,temperature, and available materials, will be able to design the mostcost effective, safe, and operable system for each particularapplication without undue experimentation.

The risers and the primary components of the LRAs, seal stems, and PBRsdescribed herein (offtake ports, intake ports, generally cylindricalmembers, high pressure subsea connectors, adapters, and the like) arelargely comprised of steel alloys. While low alloy steels may be usefulin certain embodiments where water depth is not greater than a fewthousand (for example 5000) feet (about 1524 meters), activities inwater of greater depths, with wells reaching 20,000 ft. (about 6000meters) and beyond is expected to result in operating temperatures andpressures that are well above those presently allowed in current APIspecifications. In these “high temperature, high pressure” (HTHP)applications, high strength low alloy steel metallurgies such as C-110and C-125 steel may be more appropriate. The Research Partnership toSecure Energy for America (RPSEA) and Deepstar programs have initiated along term, large scale prequalification program to develop databases offatigue data for, and derive rating factors on, high strength materialsfor riser applications with the contribution of major operators,engineering firms and material vendors. High strength steels (such asX-100, C-110, Q-125, C-125, V-140), Titanium (such as Grade 29 andpossibly newer alloys) and other possible material candidates in thehigher strength category will be tested for pipe applications, andpending those results, they may be useful as materials for the risers,LRAs, seal stems, and PBRs described herein. Higher strength forgingmaterials (such as F22, 4330M, Inconel 718 and Inconel 725) either havebeen or will soon be tested for component applications in the comingyears, and may prove useful for one or more components of the describedLRA assemblies, seal stems, PBRs and/or risers. The test matrix will bedesigned to reflect various production environments and different typesof riser configurations, such as single catenary risers (SCR's), drytree risers, and drilling and completion risers. The project iscurrently scheduled to be divided into three separate Phases. Phase 1will address tensile and fracture toughness, FCGR and S—N tests (bothsmooth and notched) on strip specimens of high strength pipes, highstrength forging materials and nickel base alloy forgings in air,seawater, seawater plus Cathodic Protection (CP) and sour environment(non-inhibited) and a completion fluid known as INSULGEL (BJ ServicesCompany, USA) with sour environment (non-inhibited) contamination(2008). Phase 2 is scheduled to be Intermediate Scale Testing (2009),and Phase 3, Full Scale Testing with H₂S/CO₂/sea water (2010). Forfurther information, see Shilling, et al., Development of FatigueResistant Heavy Wall Riser Connectors for Deepwater HPHT Dry Tree RiserSystems, OMAE (2009) 79518 (copyright 2009 ASME). See also RPSEARFP2007DW1403, Fatigue Performance of High Strength Riser Materials,Nov. 28, 2007. As stated previously, the skilled artisan, havingknowledge of the particular depth, pressure, temperature, and availablematerials, will be able design the most cost effective, safe, andoperable system for each particular application without undueexperimentation.

Materials of construction for gaskets, flexible conduits, and hosesuseful for constructing and using the systems and methods describedherein will depend on the specific water depth, temperature and pressureat which they are employed. Although elastomeric gaskets may be employedin certain situations, metal gaskets have been increasingly used insubsea application. For a review of the art circa 1992, see Milberger,et al., “Evolution of Metal Seal Principles and Their Application inSubsea Drilling and Production”, OTC-6994, Offshore TechnologyConference, Houston Tex., 1992. See also APT STD 601 —Standard forMetallic Gaskets for Raised-face Pipe flanges & Flanged Connections. Seealso API Spec 6A—Specification for Wellhead and Christmas TreeEquipment.

Gaskets are not, per se, a part of the present systems and methods, butas certain LRA embodiments may employ gaskets, mention is made of thefollowing U.S. patents which describe gaskets which may be suitable foruse in particular embodiments, as guided by the knowledge of theordinary skilled artisan: U.S. Pat. Nos. 3,637,223; 3,918,485;4,597,448; 4,294,477; and 7,467,663.

Another gasket that may be used subsea is that known under the tradedesignation Pikotek VCS, available from Pikotek, Inc., Wheat Ridge,Colo. (USA). Rather than relying strictly on a seal formed by deforminga metal ring into concentric grooves machined into opposing flangefaces, the gasket known under the trade designation Pikotek VCS uses amatrix-reinforced, high-density composite material, permanentlylaminated to a corrosion-resistant, metal alloy core (316 stainless or2205 duplex). This type of gasket is believed to be described in U.S.Pat. No. 4,776,600.

Various burst disks maybe used on subsea equipment, such as subseamanifolds. Such burst disks may in certain embodiments be retrievableburst disks. In certain embodiments the LRA may have a retrievable burstdisk, allowing venting of the LRA to the atmosphere. A burst disk mayallow pumping of a functional fluid into the LRA. Burst disks may allowpressure and/or temperature measurement of the flow stream inside theLRA or riser.

Hoses, which may also be referred to herein as flexible jumpers incertain embodiments, suitable for use in the systems and methods of thisdisclosure may be selected from a variety of materials or combination ofmaterials suitable for subsea use, in other words having hightemperature resistance, high chemical resistance and low permeationrates. Some fluoropolymers and nylons are particularly suitable for thisapplication except for conduits of extremely long length (severalkilometers or more) where permeation may be problematic. A good surveyof hoses and materials may be found in U.S. Pat. No. 6,901,968 presentlyassigned to Oceaneering International Services, London, Great Britain,which describes so called “High Collapse Resistant Hoses” of the typeused in deep sea applications, which, in use, must be able to resistcollapsing due to the very large pressures exerted thereon. The '968patent describes a fluid conduit and multi-conduit umbilicals for use inthe transportation of chemicals with small molecular size and shape, forexample methanol, ethanol and other hydrocarbon fluids used in the oilindustry. The conduit includes a flexible fluid hose encapsulated by atleast one metalized layer that is formed and arranged to minimizepermeation of a fluid being transported in the fluid hose. In use in amulti-conduit umbilical the metalized layer minimizes permeation intoadjacent fluid hoses containing chemicals. In certain embodiments it maybe necessary or desirable to splice one hose to another hose, or toreplace a damaged hose.

The systems of the present disclosure may, in certain embodiments, beinstalled by drilling MODU and then accommodate flexible jumperinstallation after the riser has been run. In embodiments using adrilling MODU, the subsea flexible 30 may be connected several dayslater to the LRA by one or more subsea installation vessels, for exampleone or more ROVs or AUVs, after the riser is stabbed into the PBR.

In certain embodiments, conventional pressure relief valves may bemodified and employed subsea, for example on various subsea manifolds,risers, and LRA. Conventional surface pressure relief valves may includea three-way valve body, a bonnet enclosing a spring, and a cap enclosingan adjusting screw for the spring, a nozzle and seat arrangement in theinlet, and an open discharge outlet. The bonnet typically has aremovable plug. These conventional pressure relief valves may bemodified or “marinized” by removing the removable plug in the bonnet anddrilling one or more holes in the cap. This allows seawater to enter thecap and bonnet, equalizing pressure there with pressure in the dischargeoutlet (local pressure at depth). The spring and nozzle in thesemodified pressure relief valves may be changed to a material morecompatible with seawater and hydrocarbon use to avoid corrosion issues.

To avoid the corrosion issues, rather than drilling one or more holes inthe cap and removing the plug from conventional pressure relief valves,a dead weight arrangement may be employed. A guided weight system may beadded to the conventional design, whereby a dead weight (for example ablock of metal) is placed in contact with the bonnet on its top, and thespring is removed. One or more guides might guide the weight. Weightscould be added or removed subsea, for example by an ROV. The weight mayseal to the upper opening of the bonnet via any of various very hard andwear-resistant alloys, such as Inconel 625 overlaid by the materialknown under the trade designation Stellite, which is an alloy containingcobalt, chromium, carbon, tungsten, and molybdenum. As a rough example,a pressure relief valve having a 3 inch (7.6 cm) diameter nozzle set torelieve at 500 psi (3.4 MPa) would require a steel weight 710 mm indiameter, 600 mm thick, weighing about 1,800 kg.

In certain embodiments a source point interface may be required toconnect the PBR and LRA to a source. For example, in the event of ablowout, in certain embodiments, a riser may be damaged and in somecases may be lying on the seabed. A riser insertion tubing tool may beemployed in those instances, the riser insertion tube connecting via aflexible conduit to the LRA. Riser insertion tubing tools and methods ofuse are described in Assignees' Attorney Docket No. 500032 correspondingto U.S. Provisional Application No. 61/479,704, filed Apr. 27, 2011,incorporated herein by reference. Subsea connectors such as those knownunder the trade designation OPTIMA mentioned herein may be employed atan interface between a flexjoint and the LMRP. If a PBR is used, amodified bumper sub having both telescoping action as well as swivelaction may be employed between the PBR and a surface vessel.

From the foregoing detailed description of specific embodiments, itshould be apparent that patentable methods and apparatus have beendescribed. Although specific embodiments of the disclosure have beendescribed herein in some detail, this has been done solely for thepurposes of describing various features and aspects of the methods andapparatus, and is not intended to be limiting with respect to the scopeof the systems, methods and apparatus. For example, vessel 28 may be asemi-submersible drilling vessel. It is contemplated that varioussubstitutions, alterations, and/or modifications, including but notlimited to those implementation variations which may have been suggestedherein, may be made to the described embodiments without departing fromthe scope of the appended claims.

1. A riser system connecting a subsea source to a surface vessel, saidsystem comprising: a near-vertical riser comprising a lower end and anupper end, the upper end of the riser mechanically and fluidly connectedto the surface vessel; a seal stem, a lower end of the riser fluidly andmechanically connected to the seal stem, the seal stem comprising one ormore exterior elastomeric sealing elements; a lower riser assemblycomprising a member having a longitudinal bore, a lower end, an upperend, and an external surface, the member comprising sufficient intakeports extending from the external surface to the bore to accommodateflow of hydrocarbons from a hydrocarbon fluid source, at least one ofthe intake ports fluidly connected to the subsea source; and a polishedbore receptacle comprising a polished bore, a lower end of the PBRfluidly and mechanically connected to the upper end of the member; theexterior elastomeric sealing elements of the seal stem sealinglyengaging the polished bore to create a pressure-tight flow path throughthe polished bore receptacle, seal stem, and riser.
 2. The riser systemaccording to claim 1, wherein the riser comprises a plurality of riserjoints.
 3. The riser system according to claim 1, wherein the vesselcomprises a dynamic positioning system, and wherein the riser ismaintained in the near-vertical position by the dynamic positioningsystem.
 4. The riser system according to claim 1, wherein the membercomprises a subsea wellhead housing having a lower end and an upper end,the lower end capped with an end forging that is attached to afoundation in the seabed.
 5. The riser system according to claim 1,wherein the seal stem comprises a latch ring that allows reduction oftravel of the seal stem in the polished bore receptacle.
 6. The risersystem according to claim 1, wherein the subsea source is fluidlyconnected to one of the intake ports via a flexible conduit and agooseneck assembly.
 7. The riser system according to claim 1, whereinthe lower riser assembly further comprises one or more hot stab portsfor ROV intervention and/or maintenance.
 8. The riser system accordingto claim 4, the wellhead housing further comprising one or more portsallowing pressure and/or temperature monitoring.
 9. The riser systemaccording to claim 1, wherein the riser upper end is connected to adrill ship or drilling rig on the vessel.
 10. The riser system accordingto claim 1, the lower end of the lower riser assembly connected to asubsea mooring, and further comprising one or more structural supportsfor the polished bore receptacle extending from the subsea mooring to apoint about midway up the polished bore receptacle.
 11. The riser systemaccording to claim 10, wherein the subsea mooring is a suction pile. 12.The riser system according to claim 4, wherein the polished borereceptacle is threaded in to the wellhead housing.
 13. The riser systemaccording to claim 1, wherein at least some portions of the risercomprise sections of pipe joined by threaded joints.
 14. The risersystem according to claim 1, wherein the riser joints are constructedusing high strength steel tubulars using threaded coupled connectors.15. The riser system according to claim 1, wherein an upper end of thepolished bore receptacle comprises a guide funnel.
 16. The riser systemaccording to claim 6, wherein the subsea flexible conduit comprises alazy wave flexible jumper with at least one distributed buoyancy moduleconnected from the base of the riser to a subsea manifold on theseafloor, the manifold fluidly connected to the subsea source.
 17. Theriser system according to claim 1, wherein the lower riser assembly isfluidly connected to an active subsea wellhead via one or more flexibleconduits.
 18. The riser system according to claim 1, wherein the lowerriser assembly comprises one or more ROV hot-stab ports allowing a flowassurance fluid to flow into both the lower riser assembly and theriser, the flow assurance fluid selected from the group consisting ofnitrogen or other gas phase, heated seawater or other water, and one ormore organic chemicals.
 19. The riser system according to claim 1,wherein the seal between the polished bore receptacle and the seal stemis such that the riser and seal stem may be disconnected from thepolished bore receptacle, allowing the polished bore receptacle andlower riser assembly to be disconnected from the surface vessel in aneither an emergency or planned event.
 20. The riser system according toclaim 1, the lower riser assembly further comprising an additionalassembly or sub fluidly connecting the lower riser assembly to a sourceof a flow assurance fluid.
 21. The riser system according to claim 6,wherein the gooseneck assembly comprises, in order starting at thegenerally cylindrical member, an API flange, a section of tubing, a highpressure subsea connector, a subsea API connector and API flange, and abend restrictor.
 22. The riser system according to claim 1, the membercomprising a forged, high-strength steel intake spool fluidly connectedto a gooseneck assembly, the gooseneck assembly fluidly connected to aflexible conduit, the member also comprising a connector allowingconnection to a source of a flow assurance fluid.
 23. The riser systemof claim 1, wherein the subsea source is a malfunctioning subsea BOP,the system further comprising one or more umbilicals, one of theumbilicals fluidly connected to locations on the subsea BOP selectedfrom the group consisting of a kill line of the subsea BOP, a choke lineof the subsea BOP, and both the kill and choke lines of the subsea BOP.24. The riser system of claim 1, wherein the subsea source is amalfunctioning subsea BOP, the system further comprising one or moreumbilicals, one of the umbilicals fluidly connected to a subsea BOPstack manifold.
 25. The riser system of claim 1, further comprising oneor more umbilicals, wherein one of the umbilicals is fluidly connectedto a subsea manifold.
 26. The riser system of claim 1, furthercomprising the seal stem extending into the member a distance sufficientto create upper and lower seals between the member and the seal stem,wherein the intake ports are between the upper and lower seals, the sealstem further comprising one or more inlet ports positioned between theupper and lower seals.
 27. A method of installing a subsea marine risersystem, the method comprising: attaching a first end of a member to anend forging, a first end of a polished bore receptacle to the member,the polished bore receptacle comprising a polished bore and a guidefunnel on an end opposite the first end, and attaching the end forgingto a subsea foundation so that the polished bore receptacle issubstantially vertical; directing a drill string riser toward the guidefunnel, the drill string comprising a seal stem comprising one or moreelastomeric seal elements; and stabbing the seal stem into the polishedbore receptacle and establishing a pressure-tight seal between theelastomeric seal elements and the polished bore.
 28. The method of claim27, further comprising: connecting a subsea flexible conduit andgooseneck assembly to the member and to a subsea source.
 29. The methodof claim 27, wherein the steps of directing and stabbing are performedusing a mobile offshore drilling unit.
 30. The method of claim 27,further comprising assisting the directing and/or the stabbing stepsusing one or more ROVs.
 31. The method of claim 27, comprisingconstructing the drill string riser using high strength steel tubularsusing threaded coupled connectors.
 32. The method of claim 27, furthercomprising supporting the polished bore receptacle using structuralsupports extending from the subsea foundation to a point approximatelymidway up the polished bore receptacle.
 33. A method of producing afluid from a subsea source, the method comprising: deploying subsea froma surface vessel a lower riser assembly (LRA) comprising a member havinga longitudinal bore, a lower end, an upper end, and an external surface,the member comprising sufficient intake ports extending from theexternal surface to the bore to accommodate flow of hydrocarbons from ahydrocarbon fluid source, the lower riser assembly having attachedthereto a polished bore receptacle comprising a polished bore, a lowerend of the polished bore receptacle fluidly and mechanically connectedto the upper end of the member; fluidly connecting at least one of theintake ports to the subsea source using a flexible conduit; lowering ariser from the surface vessel, the riser comprising a lower end and anupper end, the upper end of the riser mechanically and fluidly connectedto the surface vessel, the riser being maintained in an erectsubstantially vertical position by dynamic positioning of the vessel,the riser comprising a seal stem fluidly and mechanically connected toits lower end, the seal stem comprising one or more exterior elastomericsealing elements; stabbing the seal stem into the polished borereceptacle, the exterior elastomeric sealing elements of the seal stemsealingly engaging the polished bore to create a pressure-tight flowpath through the polished bore receptacle, seal stem, and riser; andinitiating flow from the subsea source through the subsea flexibleconduit, the lower riser assembly, the polished bore receptacle, theseal stem, and the riser.
 34. A method of killing a well producing afluid from a subsea source, the method comprising: deploying subsea froma surface vessel a lower riser assembly comprising a member having alongitudinal bore, a lower end, an upper end, and an external surface,the member comprising sufficient outtake ports extending from the boreto the external surface to accommodate flow of a kill density fluid fromthe surface vessel to a hydrocarbon fluid source, the lower riserassembly having attached thereto a polished bore receptacle comprising apolished bore, a lower end of the polished bore receptacle fluidly andmechanically connected to the upper end of the member; fluidlyconnecting at least one of the outtake ports to the subsea source usinga flexible conduit; lowering a riser from the surface vessel, the risercomprising a lower end and an upper end, the upper end of the risermechanically and fluidly connected to the surface vessel, the riserbeing maintained in an erect substantially vertical position by dynamicpositioning of the vessel, the riser comprising a seal stem fluidly andmechanically connected to its lower end, the seal stem comprising one ormore exterior elastomeric sealing elements; stabbing the seal stem intothe polished bore receptacle, the exterior elastomeric sealing elementsof the seal stem sealingly engaging the polished bore to create apressure-tight flow path through the riser, seal stem, and polished borereceptacle; and initiating flow of kill density fluid from the surfacevessel through the riser, seal stem, polished bore receptacle, lowerriser assembly, and subsea flexible conduit.
 35. A method of cementing asubsea wellbore using a surface marine vessel, the method comprising:deploying subsea from a surface vessel a lower riser assembly comprisinga member having a longitudinal bore, a lower end, an upper end, and anexternal surface, the member comprising sufficient outtake portsextending from the bore to the external surface to accommodate flow of acementing fluid from the surface vessel to a hydrocarbon fluid source,the lower riser assembly having attached thereto a polished borereceptacle comprising a polished bore, a lower end of the polished borereceptacle fluidly and mechanically connected to the upper end of themember; fluidly connecting at least one of the outtake ports to thesubsea source using a flexible conduit; lowering a riser from thesurface vessel, the riser comprising a lower end and an upper end, theupper end of the riser mechanically and fluidly connected to the surfacevessel, the riser being maintained in an erect substantially verticalposition by dynamic positioning of the vessel, the riser comprising aseal stem fluidly and mechanically connected to its lower end, the sealstem comprising one or more exterior elastomeric sealing elements;stabbing the seal stem into the polished bore receptacle, the exteriorelastomeric sealing elements of the seal stem sealingly engaging thepolished bore to create a pressure-tight flow path through the riser,seal stem, and polished bore receptacle; and initiating flow of acementing fluid from the surface vessel through the riser, seal stem,polished bore receptacle, lower riser assembly, and subsea flexibleconduit.